Wired and Wireless Downhole Telemetry Using Production Tubing

ABSTRACT

A system for downhole telemetry employs a series of communications nodes spaced along a tubular body such as a pipe in a wellbore. The nodes allow for hybrid wired-and-wireless communication between one or more sensors residing at the level of a subsurface formation, and a receiver at the surface. The communications nodes employ electro-acoustic transducers that provide for node-to-node communication partially up a wellbore, and then high speed data transmission using a wire for the remaining distance up to the surface. A method of transmitting data in a wellbore uses a plurality of data transmission nodes situated along a tubular body to deliver wireless signals partially up the wellbore, and then wired signals the remaining distance.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims benefit of U.S. Provisional Application No. 61/739,677, filed Dec. 19, 2012, and U.S. Provisional Application No. 61/798,679, filed Mar. 15, 2013 and both are incorporated by reference herein in their entirety.

BACKGROUND OF THE INVENTION

This section is intended to introduce various aspects of the art, which may be associated with exemplary embodiments of the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.

FIELD OF THE INVENTION

The present invention relates to the field of data transmission along a tubular body. More specifically, the invention relates to the transmission of data along pipes within a wellbore. The present invention further relates to a hybrid wired-and-wireless transmission system for transmitting data from a downhole formation up a string of production tubing incident to production operations.

GENERAL DISCUSSION OF TECHNOLOGY

In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. After drilling to a predetermined depth, the drill string and bit are removed and the wellbore is lined with a string of casing. An annular area is thus formed between the string of casing and the surrounding formations. A cementing operation is typically conducted in order to fill or “squeeze” the annular area with cement. The combination of cement and casing strengthens the wellbore and facilitates the isolation of formations behind the casing.

It is common to place several strings of casing having progressively smaller outer diameters into the wellbore. The process of drilling and then cementing progressively smaller strings of casing is repeated several times until the well has reached total depth. The final string of casing, referred to as a production casing, is cemented in place. This is a tubular body that resides adjacent one or more producing reservoirs, or “pay zones.” The production casing is frequently in the form of a liner, that is, a tubular body that is not tied to the surface, but is hung from a next lowest string of casing using a liner hanger. In either instance, the production casing is perforated to provide fluid communication between the reservoir and the production tubing.

In some instances, the wellbore is left uncased along the pay zones. This means that no liner string is used. This is known as an open hole completion. To support the open wellbore and to prevent the migration of sand and fines into the wellbore, a filtering screen is typically placed along the subsurface reservoirs. A column of sand may also be installed around the filtering screen, thereby forming a gravel pack.

In order to move production fluids to the surface, a string of tubing is run into the casing. A packer is set proximate a lower end of the tubing to seal an annular area formed between the tubing and the surrounding strings of casing. The tubing then becomes a string of production pipe through which hydrocarbon fluids may be lifted.

As part of the completion process, a wellhead is installed at the surface. The wellhead controls the flow of production fluids to the surface, or the injection of fluids into the wellbore. Fluid gathering and processing equipment such as pipes, valves and separators are also provided. Production operations may then commence.

It is desirable to obtain data from the wellbore after completion. In the oil and gas industry, cables and wires are routinely run into wells for observation and analysis. These may include slick lines or wire lines for formation logging operations. Such may also include the use of fixed cables for gathering data from downhole sensors.

Various wireless technologies have also been proposed or developed for downhole communications. Such technologies are referred to as telemetry.

One example of telemetry is mud pressure pulse transmission, or so-called mud pulse telemetry. Mud pulse telemetry is commonly used during drilling to obtain real time data from sensors at or near the drill bit. Mud pulse telemetry employs variations in pressure in the drilling mud to transmit signals from the bottom hole assembly to the surface. The variations in pressure may be sensed and analyzed by a computer at the surface.

Another example is acoustic telemetry. Acoustic telemetry employs an acoustic signal generated at or near the bottom of a well, such as from a bottom hole assembly during drilling. The signal is transmitted through steel pipe in the wellbore, meaning that the pipe serves as the carrier medium for sound waves. Transmitted sound waves are detected and converted to electrical signals at the surface for analysis.

U.S. Pat. No. 5,924,499 entitled “Acoustic Data Link and Formation Property Sensor for Downhole MWD System,” teaches the use of acoustic signals for “short hopping” a component along a drill string. Signals are transmitted from a drill bit or from a near-bit sub and across the mud motors. This may be done by sending separate acoustic signals simultaneously—one that is sent through the drill string, a second that is sent through the drilling mud, and optionally, a third that is sent through the formation. These signals are then processed to extract readable signals.

U.S. Pat. No. 6,912,177, entitled “Transmission of Data in Boreholes,” addresses the use of an acoustic transmitter that is as part of a downhole tool. Here, the transmitter is provided adjacent a downhole obstruction such as a shut-in valve along a drill stem so that an electrical signal may be sent across the drill stem. U.S. Pat. No. 6,899,178, entitled “Method and System for Wireless Communications for Downhole Applications,” describes the use of a “wireless tool transceiver” that utilizes acoustic signaling. Here, an acoustic transceiver is in a dedicated tubular body that is integral with a gauge and/or sensor. This is described as part of a well completion.

Another telemetry system that has been suggested involves electromagnetic (EM) telemetry. EM telemetry employs electromagnetic waves, or alternating current magnetic fields, to “jump” across pipe joints. In practice, a specially-milled drill pipe is provided that has a conductor wire machined along an inner diameter. The conductor wire transmits signals to an induction coil at the end of the pipe. The induction coil, in turn, then transmits an EM signal to another induction coil, which sends that signal through the conductor wire in the next pipe. Thus, each threaded connection provides a pair of specially milled pipe ends for EM communication.

Service company National Oilwell Varco® of Houston, Tex., offers a drill pipe network, referred to as IntelliServ®, that uses EM telemetry. The IntelliServ® system employs drill pipe having integral wires that can transmit LWD/MWD data to the surface at speeds of up to 1 Mbps. This creates a communications system from the drill string itself. The IntelliServ® communications system uses an induction coil built into both the threaded box and pin ends of each drill pipe so that data may be transmitted across each connection. Examples of IntelliServe® patents are U.S. Pat. No. 7,277,026 entitled “Downhole Component With Multiple Transmission Elements,” and U.S. Pat. No. 6,670,880 entitled “Downhole Data Transmission System.” It is observed that the induction coils in an EM telemetry system must be precisely located in the box and pin ends of the joints of the drill string to ensure reliable data transfer.

Recently, the use of radiofrequency signals has been suggested. This is offered in U.S. Pat. No. 8,242,928 entitled “Reliable Downhole Data Transmission System.” This patent suggests the use of electrodes placed in the pin and box ends of pipe joints. The electrodes are tuned to receive RF signals that are transmitted along the pipe joints having a conductor material placed there along, with the conductor material being protected by a special insulating coating. While high data transmission rates can be accomplished using RF signals in a downhole environment, the transmission range is typically limited to a few meters. This, in turn, requires the use of numerous repeaters.

A need exists for a high speed data transmission system in a wellbore that does not require the machining of induction coils with precise grooves placed into pipe ends or the need for electrodes in the pipe ends. Further, a need exists for such a transmission system that does not require the precise alignment of induction coils or the placement of RF electrodes between pipe joints. In addition, a need exists for a hybrid wired-and-wireless transmission system that allows for the wireless transmission of data from a formation up to a wired transmission system along a production tubing.

SUMMARY OF THE INVENTION

A downhole acoustic telemetry system is first provided herein. The system employs novel communications nodes spaced along pipe joints within a wellbore. The pipe joints may be, for example, joints of casing (including a liner), or joints of sand screen.

The system first comprises one or more downhole sensors. Each of the sensors resides along the wellbore proximate a subsurface formation. The subsurface formation preferably includes hydrocarbon fluids in commercially viable quantities. Each of the downhole sensors is configured to sense a subsurface condition, and then send a signal indicative of that subsurface condition.

In one aspect, the subsurface condition is pressure. In that instance, the sensor is a pressure sensor. In another aspect, the subsurface condition is temperature. In that instance, the sensor is a temperature sensor. Other types of sensors may be used. These include induction logs, gamma ray logs, formation density sensors, sonic velocity sensors, vibration sensors, resistivity sensors, flow meters, microphones, geophones, strain gauges, or combinations thereof.

The system also includes one or more sensor communications nodes, or two or more sensor communications nodes, or in some embodiments there may only be a sensor communications node for every other joint. The exact number and arrangement may depend upon factors such as signal strength, signal quality, and joint length. The sensor communications nodes also reside along the wellbore proximate a depth of the subsurface formation. Each of the sensor communications nodes has a housing. The housing is fabricated from a steel material. In one aspect, each of the communications nodes also has a sealed bore formed within the housing. The bore holds electronic components, including an electro-acoustic transducer and associated transceiver. The transceiver is designed to generate an acoustic signal along a pipe.

Each sensor communications node is independently powered. Thus, an independent power source such as a battery or a fuel cell is provided within the bore of each housing for providing power to the transceiver.

Each of the two or more downhole sensors resides within the housing of a corresponding sensor communications node. Alternatively, each of the two or more downhole sensors resides adjacent the housing of a corresponding sensor communications node, and is in electrical communication with the corresponding electro-acoustic transducer.

In one aspect, each of the sensor communications nodes includes one, and preferably two, clamps. In this way, each of the two or more sensor communications nodes is clamped onto an outer surface of a subsurface pipe, such as casing. Preferably, the sensor communications nodes are spaced at one node per joint of pipe. The two or more sensor communications nodes may be placed along 2, 10, or even 20 joints of casing, with one node per joint.

The downhole acoustic telemetry system also has a receiver. The receiver resides proximate a surface. For a land-based operation, the surface is an earth surface, preferably at or near the well head. For an offshore operation, the surface may be a production platform, a drilling rig, a floating ship-shaped vessel, or an FPSO.

The telemetry system also includes a string of production tubing. The string of production tubing resides within the wellbore. The tubing extends from the surface and down proximate the subsurface formation.

The system further includes a communications wire. The communications wire may be, for example, an insulated electrical wire or a fiber optic cable. The wire is placed substantially along a length of the string of production tubing down to the subsurface formation.

In addition, the telemetry system includes at least one receiver communications node. The receiver communications node is secured to the string of production tubing proximate the subsurface formation. The receiver communications node is configured to receive wireless signals from at least one of the sensor communications nodes, and transmit those signals via the communications wire up to the receiver.

In one aspect, each of the one or more sensor communications nodes is configured to wirelessly communicate with a corresponding receiver communications node. In this instance, each of the at least one receiver communications node is configured to receive acoustic signals from the corresponding sensor communications nodes, and transmit those signals to the receiver via the communications wire.

In another aspect, the one or more sensor communications nodes comprises a series of acoustic sensor nodes configured to transmit wireless signals up to a receiver communications node, node-to-node, using the subsurface pipe as a carrier medium. In this instance, the at least one receiver communications node comprises a single receiver communications node.

The acoustic signals or waves represent the data generated by the sensor. In this way, data about subsurface conditions are transmitted from node-to-node up to the receiver communications node. In one aspect, the communications nodes transmit data as mechanical waves at a rate exceeding about 50 bps. In a preferred embodiment, multiple frequency shift keying (MFSK) is the modulation scheme enabling the transmission of information up to a receiver communications node.

A separate method of transmitting data along a wellbore and up to a surface is also provided herein. The method uses a plurality of data transmission nodes situated along a tubular body to accomplish a hybrid wired-and-wireless transmission of data along the wellbore. The wellbore penetrates into a subsurface formation, allowing for the communication of a wellbore condition at the level of the subsurface formation up to the surface.

The method first includes placing one or more downhole sensors along the wellbore. The sensors are placed proximate a depth of the subsurface formation. In one aspect, the sensors reside within the housing of a respective sensor communications node, such as the communications nodes described above. Alternatively, each of the one or more downhole sensors resides adjacent the housing of a corresponding sensor communications node, and is in electrical communication with the corresponding electro-acoustic transducer of the communications node. This is preferably by means of a short wired connection.

The method also includes generating signals at the downhole sensors. The signals are indicative of one or more sensed subsurface conditions. In one aspect, the subsurface condition is pressure. In that instance, the sensors are pressure sensors. In another aspect, the subsurface condition is temperature. In that instance, the sensors are temperature sensors. Other types of sensors may be used as noted above.

The method further includes providing one or more sensor communications nodes along the wellbore. The sensor communications nodes are also placed proximate a depth of the subsurface formation. Each sensor communications node is configured to process the signals generated by a corresponding downhole sensor, and then transmit those signals as acoustic signals.

The method also comprises providing a receiver at a surface. For a land-based operation, the surface is an earth surface, preferably at or near the well head. For an offshore operation, the surface may be a production platform, a drilling rig, a floating ship-shaped vessel, or an FPSO.

The method also includes running a production tubing into the wellbore. The production tubing has a communications wire placed substantially along its length. The communications wire extends from the receiver and down the joints of pipe making up the production tubing.

The method also offers the step of securing at least one receiver communications node onto the production tubing. The receiver communications nodes are placed proximate the subsurface formation. The at least one receiver communications node is configured to receive wireless signals from at least one of the sensor communications nodes, and transmit those signals via the communications wire to the receiver as described above.

Electrical signals are sent by the receiver communications node, up the communications wire, and to the receiver. The method then includes processing signals received by the receiver for analysis of the one or more subsurface conditions.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the present inventions can be better understood, certain drawings, charts, graphs and/or flow charts are appended hereto. It is to be noted, however, that the drawings illustrate only selected embodiments of the inventions and are therefore not to be considered limiting of scope, for the inventions may admit to other equally effective embodiments and applications.

FIG. 1A is a side, cross-sectional view of an illustrative wellbore. The wellbore has been completed as a cased hole completion. A series of communications nodes is placed along a horizontal portion of the wellbore. The communications nodes transmit signals to a single receiver communications node uphole.

FIG. 1B is a cross-sectional view of a wellbore having been completed in an alternate manner. Here, the illustrative wellbore has been completed as an open hole completion. A series of communications nodes is placed along the base pipe of a sand screen in the open hole completion as part of a telemetry system.

FIG. 2 is another side, cross-sectional view of a wellbore. The wellbore has been completed as a cased hole completion. A series of communications nodes is again placed along a horizontal portion of the wellbore. Here, the communications nodes transmit signals to corresponding receiver communications nodes.

FIG. 3 is a perspective view of an illustrative pipe joint. An electro-acoustical communication node is shown exploded away from the pipe joint.

FIG. 4A is a perspective view of a communications node as may be used in the electro-acoustical data transmission systems of the present invention, in one embodiment.

FIG. 4B is a cross-sectional view of the communications node of FIG. 4A. The view is taken along the longitudinal axis of the node. Here, a sensor is provided within the communications node.

FIG. 4C is another cross-sectional view of the communications node of FIG. 4A, in an alternate embodiment. The view is again taken along the longitudinal axis of the node. Here, a sensor resides along the wellbore external to the communications node.

FIGS. 5A and 5B are perspective views of a shoe as may be used on opposing ends of the communications node of FIG. 4A, in one embodiment. In FIG. 5A, the leading edge, or front, of the shoe is seen. In FIG. 5B, the back of the shoe is seen.

FIG. 6 is a perspective view of a portion of a communications node system of the present invention, in one embodiment. The illustrative communications node system utilizes a pair of clamps for connecting a communications node onto a tubular body.

FIG. 7 is a flowchart demonstrating steps of a method for transmitting data in a wellbore in accordance with the present inventions, in one embodiment.

DETAILED DESCRIPTION OF CERTAIN EMBODIMENTS Definitions

As used herein, the term “hydrocarbon” refers to an organic compound that includes primarily, if not exclusively, the elements hydrogen and carbon. Examples of hydrocarbons include any form of natural gas, oil, coal, and bitumen that can be used as a fuel or upgraded into a fuel.

As used herein, the term “hydrocarbon fluids” refers to a hydrocarbon or mixtures of hydrocarbons that are gases or liquids. For example, hydrocarbon fluids may include a hydrocarbon or mixtures of hydrocarbons that are gases or liquids at formation conditions, at processing conditions, or at ambient conditions (20° C. and 1 atm pressure). Hydrocarbon fluids may include, for example, oil, natural gas, gas condensates, coal bed methane, shale oil, shale gas, and other hydrocarbons that are in a gaseous or liquid state.

As used herein, the term “subsurface” refers to geologic strata occurring below the earth's surface.

As used herein, the term “sensor” includes any electrical sensing device or gauge. The sensor may be capable of monitoring or detecting pressure, temperature, fluid flow, vibration, resistivity, or other formation data.

As used herein, the term “formation” refers to any definable subsurface region. The formation may contain one or more hydrocarbon-containing layers, one or more non-hydrocarbon containing layers, an overburden, and/or an underburden of any geologic formation.

The terms “zone” or “zone of interest” refer to a portion of a subsurface formation containing hydrocarbons. The term “hydrocarbon-bearing formation” may alternatively be used.

As used herein, the term “wellbore” refers to a hole in the subsurface made by drilling or insertion of a conduit into the subsurface. A wellbore may have a substantially circular cross section, or other cross-sectional shape. As used herein, the term “well,” when referring to an opening in the formation, may be used interchangeably with the term “wellbore.”

The terms “tubular member,” “tubular body” or “subsurface pipe” refer to any pipe, such as a joint of casing, a portion of a liner, a production tubing, an injection tubing, a pup joint, underwater piping, or a base pipe in a sand screen.

Description of Selected Specific Embodiments

The inventions are described herein in connection with certain specific embodiments. However, to the extent that the following detailed description is specific to a particular embodiment or a particular use, such is intended to be illustrative only and is not to be construed as limiting the scope of the inventions.

FIG. 1A is a side, cross-sectional view of an illustrative well site 100. The well site 100 includes a wellbore 150 that penetrates into a subsurface formation 155. The wellbore 150 has been completed as a cased-hole completion for producing hydrocarbon fluids.

The well site 100 includes a well head 160. The well head 160 is positioned at an earth surface 101 over the wellbore 150. The well head 160 controls and directs the flow of formation fluids from the subsurface formation 155 to the surface 101.

The well head 160 may be any arrangement of pipes or valves that receives reservoir fluids at the top of the well. In the arrangement of FIG. 1A, the well head 160 is a so-called Christmas tree. A Christmas tree is typically used when the subsurface formation 155 has enough in situ pressure to drive production fluids from the formation 155, up the wellbore 150, and to the surface 101. The illustrative well head 160 includes a top valve 162 and a bottom valve 164. In some contexts, these valves are referred to as “master valves.”

It is understood that rather than using a Christmas tree, the well head 160 may alternatively include a motor (or prime mover) at the surface 101 that drives a pump. The pump, in turn, reciprocates a set of sucker rods and a connected positive displacement pump (not shown) downhole. The pump may be, for example, a rocking beam unit or a hydraulic piston pumping unit. Alternatively still, the well head 160 may be configured to support a string of production tubing having a downhole electric submersible pump, a gas lift valve, or other means of artificial lift (not shown). The present inventions are not limited by the configuration of pumping equipment unless expressly noted in the claims.

Referring now to the wellbore 150, the wellbore 150 has been completed with a series of pipe strings, referred to as casing. First, a string of surface casing 110 has been cemented into the formation. Cement is shown in an annular space 115 within the wellbore 150 surrounding the casing 110. The surface casing 110 has an upper end in sealed connection with the lower valve 164.

Next, at least one intermediate string of casing 120 is cemented into the wellbore 150. The intermediate string of casing 120 is in sealed fluid communication with the upper master valve 162. Cement is again shown in an annular space 115 of the wellbore 150. The combination of the casing strings 110, 120 and the cement sheath in the annulus 115 strengthens the wellbore 150 and facilitates the isolation of formations behind the casing 110, 120.

It is understood that a wellbore 150 may, and typically will, include more than one string of intermediate casing. Some of the intermediate casing strings may be only partially cemented into place, depending on regulatory requirements and the presence of migratory fluids in any adjacent strata. In some instances, an intermediate string of casing may be a liner.

Finally, a production string 130 is provided. The production string 130 is hung from the intermediate casing string 120 using a liner hanger 132. The production string 130 is a liner that is not tied back to the surface 101. A portion of the production liner 130 may optionally be cemented in place.

The production liner 130 has a “lower” end 134 that extends substantially to an end 154 of the wellbore 150. For this reason, the wellbore 150 is said to be completed as a cased-hole well. In one aspect, the production string 130 is not a liner but is a casing string that extends back to the surface 101.

In order to create fluid communication between a bore 135 of the liner 130 and the surrounding rock matrix making up the subsurface formation 155, the liner 130 has been perforated. Perforations are seen at 159. In the view of FIG. 1A, perforations 159 are provided in three separate zones 102, 104, 106. Each zone may represent, for example, a length of up to about 100 feet (30 meters). While only three sets of perforations 159 are shown, it is understood that the horizontal portion 105 may have many more sets of perforations 159 in additional zones.

To enhance the exposure of the rock formation 155 to the pipe bore 135, the operator will fracture the formation 155. This is done by injecting a fracturing fluid under high pressure through the perforations 159 and into the formation 155. The fracturing process creates fractures 108 along a horizontal portion 105 of the wellbore 250. Where the natural or hydraulically-induced fracture plane(s) of a formation is vertical, a horizontally completed wellbore (portion 105) allows the production casing 130 to intersect multiple fracture planes. Horizontal completions are common for wells that are completed in so-called “tight” or “unconventional” formations. However, the present inventions have equal utility in vertically completed wells or in multi-lateral deviated wells.

The wellbore 150 also includes a string of production tubing 140. The production tubing 140 extends from the well head 160 down to the subsurface formation 155. In the arrangement of FIG. 1A, the production tubing 140 terminates proximate an upper end of the subsurface formation 155. A production packer 142 is provided at a lower end of the production tubing 140 to seal off an annular region 145 between the tubing 140 and the surrounding production liner 130. However, the production tubing 140 may extend closer to the end 134 of the liner 130.

The production tubing 140 is made up of a series of pipe joints. The joints are typically 30 to 40 feet in length. The pipe joints are threadedly coupled, and then lowered into the wellbore 150 during completion.

It is desirable to monitor subsurface conditions below the level of the production tubing 130. To accomplish this, a series of novel communications nodes is provided. The communications nodes are referred to as sensor communications nodes, and are indicated at 170. The nodes 170 are shown spaced along the production casing 130.

FIG. 3 offers an enlarged perspective view of a communication node 350 and an associated pipe joint 300. The illustrative communications node 350 is shown exploded away from the pipe joint 300 for clarity.

The illustrated pipe joint 300 is intended to represent a joint of production casing, but such tubular may be a joint of drill pipe, pipeline pipe, or other conductive tubular member. The pipe joint 300 has an elongated wall 310 defining an internal bore 315. The bore 315 transmits hydrocarbon fluids during an oil and gas production operation. The pipe joint 300 illustrates a box end 322 either manufactured onto the end of the joint or is installed such as with a threaded connecting collar having internal threads, and a pin end 324 having external threads. The communications node 350 resides intermediate the box end 322 and the pin end 324.

The communications node 350 shown in FIG. 3 is designed to be pre-welded onto the wall 310 of the pipe joint 300. Alternatively, the communications node 350 may be glued to the wall 310 using an adhesive such as epoxy. However, it is preferred that the communications node 350 be configured to be selectively attachable to/detachable from a pipe joint 300 by mechanical means at the well site 100. This may be done, for example, through the use of clamps. Such a clamping system is shown at 600 in FIG. 6, described more fully below. In any instance, the communications node 350 offers an independently-powered, electro-acoustical communications device that is designed to be attached to an external surface of a well pipe 300.

There are benefits to the use of an externally-placed communications node that uses acoustic waves. For example, such a node will not interfere with the flow of fluids within the internal bore 315 of the pipe joint 300. Further, installation and mechanical attachment can be readily assessed or adjusted, as necessary. Because the acoustic signals are carried by the wall 310 of the pipe joint 300 itself, the data is largely unaffected by the fluids in the pipe joint 300.

In FIG. 3, the communications node 350 includes an elongated body 351. The body 351 supports one or more batteries, shown schematically at 352. The body 351 also supports an electro-acoustic transducer, shown schematically at 354. The electro-acoustic transducer 354 is associated with a transceiver that can either receiver or deliver acoustic signals along the wall 310 of the pipe joint 300.

In operation, each sensor communications node 170 is in electrical communication with a sensor. This may be by means of a short wire, or by means of wireless communication such as infrared or radio-frequency communication. The sensor communications nodes 170 are configured to receive signals from the sensors, wherein the signals represent a subsurface condition. The subsurface condition may be pressure. A pressure sensor may be, for example, a sapphire gauge or a quartz gauge. Sapphire gauges are preferred as they are considered more rugged for the high-temperature downhole environment. Alternatively, the sensors may be temperature sensors. Alternatively, the sensors may be microphones for detecting ambient noise, or geophones (such as a tri-axial geophone) for detecting the presence of micro-seismic activity. Alternatively still, the sensors may be fluid flow measurement devices such as a spinners, or fluid composition sensors, or formation sensors. The sensors may alternatively be strain gauges.

FIG. 4A is a perspective view of a sensor communications node 400 as may be used in the wellbore 150 of FIG. 1A, in one embodiment. The sensor communications node 400 is designed to provide acoustic communication using a transceiver within a novel downhole housing assembly. FIG. 4B is a cross-sectional view of the communications node 400 of FIG. 4A. The view is taken along the longitudinal axis of the node 400. The sensor communications node 400 will be discussed with reference to FIGS. 4A and 4B, together.

The sensor communications node 400 first includes a housing 410. The housing 410 is designed to be attached to an outer wall of a joint of wellbore pipe, such as the pipe joint 300 of FIG. 3. Where the wellbore pipe is a carbon steel pipe joint such as drill pipe, casing or liner, the housing is preferably fabricated from carbon steel. This metallurgical match avoids galvanic corrosion at the coupling.

The housing 410 is dimensioned to be strong enough to protect internal electronics. In one aspect, the housing 410 has an outer wall 412 that is about 0.2 inches (0.51 cm) in thickness. A bore 405 is formed within the wall 412. The bore 405 houses the electronics, shown in FIG. 4B as a battery 430, a power supply wire 435, a transceiver 440, and a circuit board 445. The circuit board 445 will preferably include a micro-processor or electronics module that processes acoustic signals. An electro-acoustic transducer 442 is provided to convert acoustical energy to electrical energy (or vice-versa) and is coupled with outer wall 412 on the side attached to the tubular body. The transducer 442 is in electrical communication with a sensor 432.

It is noted that in FIG. 4B, the sensor 432 resides within the housing 410 of the communications node 400. However, as noted, the sensor 432 may reside external to the communications node 400, such as above or below the node 400 along the wellbore 150. In FIG. 4C, a dashed line is provided showing an extended connection between an external sensor 432 and an electro-acoustic transducer 442.

In either arrangement, the sensor 432 may be, for example, (i) a pressure sensor, (ii) a temperature sensor, (iii) an induction log, (iv) a gamma ray log, (v) a formation density sensor, (vi) a sonic velocity sensor, (vii) a vibration sensor, (viii) a resistivity sensor, (ix) a flow meter, (x) a microphone, (xi) a geophone, (xii) a strain gauge, or (xiii) a combinations thereof. In one aspect, the transducer 442 is the sensor itself. This allows active acoustic response along a section of casing, thereby allowing the operator to evaluate cement integrity.

In the arrangement of FIG. 1A, each sensor communications node 170 receives signals from a corresponding sensor (shown at 432 in FIGS. 4B/4C). Those signals are converted to acoustic signals, and then transmitted through the pipe to a next sensor communications node 170. Such acoustic waves are preferably at a frequency of between about 50 kHz and 500 kHz. More preferably, the acoustic wave are transmitted at a frequency of between about 100 kHz and 125 kHz. Those acoustic signals may be digitized by the micro-processor.

In one preferred embodiment, the acoustic telemetry data transfer is accomplished using multiple frequency shift keying (MFSK). Any extraneous noise in the signal is moderated by using well-known conventional analog and/or digital signal processing methods. This noise removal and signal enhancement may involve conveying the acoustic signal through a signal conditioning circuit using, for example, a bandpass filter.

The transceiver will also produce acoustic telemetry signals. In one preferred embodiment, an electrical signal is delivered to an electromechanical transducer, such as through a driver circuit. In a preferred embodiment, the transducer is the same electro-acoustic transducer that originally received the MFSK data. The signal generated by the electro-acoustic transducer then passes through the housing 410 to the tubular body, that is, the liner 130, and propagates along the tubular body to a next sensor communication nodes 170. The re-transmitted signal represents the same sensor data originally transmitted by sensor communications node 170. In one aspect, the acoustic signal is generated and received by a magnetostrictive transducer comprising a coil wrapped around a core as the transceiver. In another aspect, the acoustic signal is generated and received by a piezoelectric ceramic transducer. In either case, the filtered signal is delivered up to a receiver communications node 180.

The communications node 400 optionally has a protective outer layer 425. The protective outer layer 425 reside external to the wall 412 and provides an additional thin layer of protection for the electronics. The communications node 400 is also fluid-sealed within the housing 410 to protect the internal electronics. Additional protection for the internal electronics is available using an optional potting material.

The communications node 400 also optionally includes a shoe 500. More specifically, the node 400 includes a pair of shoes 500 disposed at opposing ends of the wall 412. Each of the shoes 500 provides a beveled face that helps prevent the node 400 from hanging up on an external tubular body or the surrounding earth formation, as the case may be, during run-in or pull-out. The shoes 500 may have a protective outer layer 422 and an optional cushioning material 424 (shown in FIG. 4A) under the outer layer 422.

FIGS. 5A and 5B are perspective views of an illustrative shoe 500 as may be used on an end of the communications node 400 of FIG. 4A, in one embodiment. In FIG. 5A, the leading edge or front of the shoe 500 is seen, while in FIG. 4B the back of the shoe 500 is seen.

The shoe 500 first includes a body 510. The body 510 includes a flat under-surface 512 that butts up against opposing ends of the wall 412 of the communications node 400.

Extending from the under-surface 512 is a stem 520. The illustrative stem 520 is circular in profile. The stem 520 is dimensioned to be received within opposing recesses 414 of the wall 412 of the node 400.

Extending in an opposing direction from the body 510 is a beveled surface 530. As noted, the beveled surface 530 is designed to prevent the communications node 400 from hanging up on an object during run-in into a wellbore.

Behind the beveled surface 530 is a flat surface 535. The flat surface 535 is configured to extend along the drill string 160 (or other tubular body) when the communications node 400 is attached to the tubular body 300. In one aspect, the shoe 500 includes an optional shoulder 515. The shoulder 515 creates a clearance between the flat surface 535 and the tubular body opposite the stem 520.

Referring again to FIG. 1A, it is observed that not every sensor communications node 170 need have a sensor. In some instances, a sensor communications node 170 may simply be conveying signals from one adjacent communications node to the next. In this way, acoustic signals are transmitted up the liner string, node-to-node.

The acoustic signals are ultimately delivered to a receiver communications node 180. The receiver communications node 180 resides at the end of the production tubing 140. The receiver communications node 180 receives wireless signals, which can be in the form of one or more of low or high frequency acoustic waves, radio waves, low frequency or inductive electromagnetic waves, and light, sent up the wellbore 150, and converts those signals into digitized electrical signals or optical signals. Those signals, in turn, are then sent on to the surface 101 by means of a communications wire 185.

The communications wire 185 extends from the receiver communications node 180 to a receiver 190. In the wellbore 150, the communications wire 185 may be an insulated electrical cable. Alternatively, the communications wire 185 may be a fiber optic cable. From the wellhead 160, the communications wire 185 will connect to the receiver 190. At the surface, the wire may be a co-axial cable, a fiber optic cable, a USB cable, or other electrical or optical communications wire. The receiver 190 preferably receives electrical signals from the well head 160 via a so-called Class I, Division I conduit, that is, housing for wiring that is considered acceptably safe in an explosive environment. In some applications, radio, infrared or microwave signals may be utilized.

The receiver 190 comprises a processor 192 that receives signals sent from the receiver communications node 180. The processor 192 may be incorporated into a computer having a screen. The computer may have a separate keyboard 194, as is typical for a desk-top computer, or an integral keyboard as is typical for a laptop or a personal digital assistant. In one aspect, the processor 192 is part of a multi-purpose “smart phone” having specific applications, or “apps,” and wireless connectivity.

It is noted that the receiver communications node 180 may be constructed in accordance with the sensor communications node 400. The receiver communications node 180 may receive acoustic signals through, for example, a centralizer (not shown) mechanically connecting the production tubing 140 with the surrounding liner string 130. In this event, it is preferred that the packer 142 be placed higher up the production tubing 140 to allow reverberation to take place at the bottom of the tubing 140.

As noted, the receiver communications node 180 converts the wireless signals to signals that may be transmitted through the communications wire 185. Use of the communications wire 185 allows for a high rate of data transmission. The wire also allows electrical energy to be sent down to the receiver communications node 180, dispensing with the need for a battery or, alternatively, allowing a battery to be re-charged.

FIG. 1A shows a wellbore 150 having been completed as a cased hole completion. However, FIG. 1B shows the same wellbore 150′ having been completed as an open hole completion. A horizontal portion 105′ of the wellbore 150′ is again shown. In FIG. 1B, a sand screen 130′ has been placed below the packer 142. Residing within the sand screen 130′ is an elongated base pipe 135′. The slotted base pipe 135′ extends below the production tubing 130. The base pipe 135′ is slotted to allow in ingress of filtered formation fluids into the wellbore 150′. The base pipe 135′ is in fluid communication with the production tubing 140.

It is understood that the sand screen 130′ is actually a series of joints of screen, with each joint having a filter medium wrapped or wound around the base pipe 135′. It is preferred, though not required, to place a gravel slurry (not shown) around the screen joints to support the surrounding formation 155 and to provide further fluid filtering. The use of sand screens with gravel packs allows for greater fluid communication with the surrounding rock matrix while still providing support for the wellbore 150′.

Because the wellbore 150′ is completed as an open hole, the production casing need not extend below the packer 142. No perforations or fractures are needed. Therefore, these aspects of the horizontal portion of the wellbore 150′ are not seen.

In the wellbore arrangement of FIG. 1B, sensor communications nodes 170′ reside along the slotted base pipe 135′. The sensor communications nodes 170′ may sense, for example, temperature and/or pressure along the sand screen 130′. The sensor communications nodes 170′ send wireless signals to the single receiver communications node 180 using the base pipe 135′ as the carrier medium.

Of interest, the communications wire 180 of FIG. 1B may be used to send a signal from the surface 101 and down to a selected sensor communications node 170′. That communications node, in turn, may send a signal to cause a sliding sleeve 175 residing along the base pipe 135′ to open. Different signals may be sent to different sliding sleeves 175, telling a sleeve to open further, to close further, or to completely close. This allows the operator to control an ingress of the production fluids along selected portions of the formation. This is particularly beneficial for wells having horizontal completions that extend many thousands of feet.

A similar arrangement may be provided in the cased hole completion of FIG. 1A. In this respect, signals may be sent down the communications wire 185 to adjust an inflow control device or a sliding sleeve. In addition, a signal may be sent to “wake up” the sensor communications nodes 170 and cause them to resume the transmission of signals, or to power batteries 430. Beneficially, electrical energy may be sent down the communications wire 185 to recharge batteries in the sensor communications nodes.

FIGS. 1A and 1B present a downhole telemetry system that employs a hybrid wired-and-wireless data transmission system. In this respect, a series of communications nodes 170/170′ transmit data wirelessly up to a receiver communications node 180, which then sends signals up a long communications wire 185. In this way, data is transmitted to the surface 101. In the arrangement of FIGS. 1A and 1B, only a single receiver communications node 180 is used; however, in an alternate arrangement, a series of receiver communications nodes are offered which correspond to specific sensor communications nodes.

FIG. 2 is a cross-sectional view of a well site 200, with a wellbore 250 having been completed in an alternate manner. The wellbore 250 in FIG. 2 is identical to the wellbore 150 in FIG. 1A. However, in FIG. 2 a series of receiver communications nodes 280 is employed.

The receiver communications nodes 280 are affixed to an outer diameter of the production tubing 240. The production tubing 240 extends down into the horizontal portion 205 of the wellbore 250 so that a receiver communications node 280 is generally adjacent to a corresponding sensor communications node 270. In this way, each sensor communications node communicates 270 wirelessly, such as acoustically or via other energy transmission, with a dedicated receiver communications node 280.

In order to transmit signals up the wellbore 250, a communications wire 285 is provided. The wire 285 extends from the surface 101 and down to each of the receiver communications nodes 280. This allows for a high speed transmission of data up to the surface 101 in a novel manner. In addition, signals may be sent down the communications wire 285 to “wake up” sensor communications nodes 270 after a period of rest. Signals may also be sent down the communications wire 285 to change the position of an inflow control device or sleeve.

FIGS. 1A, 1B and 2 present illustrative wellbores 150, 250 having a downhole telemetry system that uses a series of electro-acoustic transducers and associated transceivers. In each of FIGS. 1A, 1B and 2, the top of the drawing page is intended to be toward the surface and the bottom of the drawing page toward the well bottom. While wells commonly are completed in substantially vertical orientation, it is understood that wells may also be inclined and even horizontally completed. When the descriptive terms “up” and “down” or “upper” and “lower” or similar terms are used in reference to a drawing, they are intended to indicate location on the drawing page, and not necessarily orientation in the ground, as the present inventions have utility no matter how the wellbore is orientated.

In each of FIGS. 1A, 1B and 2, the communications nodes 180, 280 are specially designed to withstand the same corrosion and environmental conditions (i.e., high temperature, high pressure) of a wellbore 150 or 250 as the casing strings, drill string, or production tubing. To do so, it is preferred that the communications nodes 180, 280 include sealed steel housings for holding the electronics.

In one arrangement, the communications nodes (such as nodes 400 with the shoes 500) are welded onto an inner or outer surface of the tubular body, such as wall 310 of the pipe joint 300. More specifically, the body 410 of the respective communications nodes 400 are welded onto the wall of the tubular body. In some cases, it may not be feasible or desirable to pre-weld the communications nodes 400 onto pipe joints before delivery to a well site. Further still, welding may degrade the tubular integrity or damage electronics in the housing 410. Therefore, it is desirable to utilize a clamping system that allows a drilling or service company to mechanically connect/disconnect the communications nodes 400 along a tubular body as the tubular body is being run into a wellbore.

FIG. 6 is a perspective view of a portion of a communications node system 600 of the present invention, in one embodiment. The communications node system 600 utilizes a pair of clamps 610 for mechanically connecting a communications node 400 onto a tubular body 630.

The system 600 first includes at least one clamp 610. In the arrangement of FIG. 6, a pair of clamps 610 is used. Each clamp 610 abuts the shoulder 515 of a respective shoe 500. Further, each clamp 610 receives the base 535 of a shoe 500. In this arrangement, the base 535 of each shoe 500 is welded onto an outer surface of the clamp 610. In this way, the clamps 610 and the communications node 400 become an integral tool.

The illustrative clamps 610 of FIG. 6 include two arcuate sections 612, 614. The two sections 612, 614 pivot relative to one another by means of a hinge. Hinges are shown in phantom at 615. In this way, the clamps 610 may be selectively opened and closed.

Each clamp 610 also includes a fastening mechanism 620. The fastening mechanisms 620 may be any means used for mechanically securing a ring onto a tubular body, such as a hook or a threaded connector. In the arrangement of FIG. 6, the fastening mechanism is a threaded bolt 625. The bolt 625 is received through a pair of rings 622, 624. The first ring 622 resides at an end of the first section 612 of the clamp 610, while the second ring 624 resides at an end of the second section 614 of the clamp 610. The threaded bolt 625 may be tightened by using, for example, one or more washers (not shown) and threaded nuts 627.

In operation, a clamp 610 is placed onto the tubular body 630 by pivoting the first 612 and second 614 arcuate sections of the clamp 610 into an open position. The first 612 and second 614 sections are then closed around the tubular body 630, and the bolt 625 is run through the first 622 and second 624 receiving rings. The bolt 625 is then turned relative to the nut 627 in order to tighten the clamp 610 and connected communications node 400 onto the outer surface of the tubular body 630. Where two clamps 610 are used, this process is repeated.

The tubular body 630 may be, for example, a string of casing, such as the casing string 130 of FIG. 1A. The wall 412 of the communications node 400 is ideally fabricated from a steel material having a resonance frequency compatible with the resonance frequency of the tubular body 630. In addition, the mechanical resonance of the wall 412 is at a frequency contained within the frequency band used for telemetry.

In one aspect, the communications node 400 is about 12 to 16 inches (0.30 to 0.41 meters) in length as it resides along the tubular body 630. Specifically, the housing 410 of the communications node may be (0.20 to 0.25 meters) in length, and each opposing shoe 500 may be 2 to 5 inches (0.05 to 0.13 meters) in length. Further, the communications node 400 may be about 1 inch in width and 1 inch in height. The housing 410 of the communications node 400 may have a concave profile that generally matches the radius of the tubular body 630.

A method for transmitting data in a wellbore is also provided herein. The method preferably employs the communications node 400 and the clamps 610 of FIG. 6.

FIG. 7 provides a flow chart for a method 700 of transmitting date in a wellbore. The method 700 uses a plurality of communications nodes situated along a tubular body to accomplish a hybrid wired-and-wireless transmission of data along the wellbore. The wellbore penetrates into a subsurface formation, allowing for the communication of a wellbore condition at the level of the subsurface formation up to the surface.

The method 700 first includes placing one or more downhole sensors along the wellbore. This is shown at Box 710. The sensors are placed proximate a depth of the subsurface formation. The sensors may be, for example, pressure sensors, temperature sensors, formation logging tools or casing strain gauges.

The method 700 also includes generating signals at the downhole sensors. This is provided at Box 720. The signals are indicative of subsurface conditions.

The method 700 further includes providing one or more sensor communications nodes along the wellbore. This is indicated at Box 730. The sensor communications nodes are also placed proximate a depth of the subsurface formation. Preferably, the sensors from step 710 reside within a housing of an associated sensor communications node. Also, the sensor communications nodes are preferably clamped to an outer surface of a string of production casing.

Each of the sensor communications nodes has an independent power source. The independent power source may be, for example, batteries or a fuel cell. In addition, each of the communications nodes has an electro-acoustic transceiver for sending and receive acoustic waves. Preferably, a frequency would be selected that is between about 100 kHz and 125 kHz to more closely match the anticipated resonance frequency of the pipe material itself.

The sensor communications nodes are configured to transmit signals indicative of the subsurface conditions acoustically. In one aspect, piezo wafers or other piezoelectric elements are used to transmit the acoustic signals. In another aspect, multiple stacks of piezoelectric crystals or other magnetostrictive devices are used. Signals are created by applying electrical signals of a designated frequency across one or more piezoelectric crystals, causing them to vibrate at a rate corresponding to the frequency of the desired acoustic signal.

In one aspect, the data transmitted between the nodes is represented by acoustic waves according to a multiple frequency shift keying (MFSK) modulation method. Although MFSK is well-suited for this application, its use as an example is not intended to be limiting. It is known that various alternative forms of digital data modulation are available, for example, frequency shift keying (FSK), multi-frequency signaling (MF), phase shift keying (PSK), pulse position modulation (PPM), and on-off keying (OOK). In one embodiment, every 4 bits of data are represented by selecting one out of sixteen possible tones for broadcast.

Acoustic telemetry along tubulars is characterized by multi-path or reverberation which persists for a period of milliseconds. As a result, a transmitted tone of a few milliseconds duration determines the dominant received frequency for a time period of additional milliseconds. Preferably, the communication nodes determine the transmitted frequency by receiving or “listening to” the acoustic waves for a time period corresponding to the reverberation time, which is typically much longer than the transmission time. The tone duration should be long enough that the frequency spectrum of the tone burst has negligible energy at the frequencies of neighboring tones, and the listening time must be long enough for the multipath to become substantially reduced in amplitude. In one embodiment, the tone duration is 2 ms, then the transmitter remains silent for 48 milliseconds before sending the next tone. The receiver, however, listens for 2+48=50 ms to determine each transmitted frequency, utilizing the long reverberation time to make the frequency determination more certain. Beneficially, the energy required to transmit data is reduced by transmitting for a short period of time and exploiting the multi-path to extend the listening time during which the transmitted frequency may be detected.

In one embodiment, an MFSK modulation is employed where each tone is selected from an alphabet of 16 tones, so that it represents 4 bits of information. With a listening time of 50 ms, for example, the data rate is 80 bits per second.

The tones are selected to be within a frequency band where the signal is detectable above ambient and electronic noise at least two nodes away from the transmitter node so that if one node fails, it can be bypassed by transmitting data directly between its nearest neighbors above and below. In one example the tones are evenly spaced in period within a frequency band from about 50 kHz to 500 kHz.

In one aspect, the electro-acoustic transceivers in the sensor communications nodes receive acoustic waves at a first frequency, and re-transmit the acoustic waves at a second different frequency. The electro-acoustic transceivers listen for the acoustic waves generated at the first frequency for a longer time than the time for which the acoustic waves were generated at the first frequency by a previous communications node.

The method 700 additionally includes providing a receiver. This is indicated at Box 740. The receiver is positioned at the surface, such as proximate a wellhead or on an offshore platform.

The method 700 also includes running a string of production tubing into the wellbore. This is provided at Box 750. The tubing is designed to receive and to direct production fluids up to the surface. The tubing includes a communications wire that extends from the surface and substantially along its length.

The method 700 further includes attaching at least one receiver communications node to the production tubing. This is seen at Box 760. The receiver communications node is placed proximate the subsurface formation. The receiver communications node is configured to receive wireless signals in the form of one or more of low or high frequency acoustic waves, radio waves, low frequency or inductive electromagnetic waves, and light, from at least one of the sensor communications nodes, and then transmit those signals to the receiver at the surface. The signals are indicative of one or more subsurface conditions.

In one aspect, only one receiver communications node is provided. This receiver communications node is clamped or otherwise placed near the end of the production tubing. This is in accordance with the telemetry arrangement shown in FIGS. 1A and 1B. In this arrangement, acoustic signals are sent from node-to-node by the sensor communications nodes, and wirelessly up to the receiver communications node. The receiver communications node, in turn, sends an electrical or optic signal up to the receiver via the communications wire.

In another aspect, a plurality of receiver communications nodes is provided. These receiver communications nodes are spaced apart along the production tubing, with the production tubing extending down through the production casing. This is in accordance with the telemetry arrangement shown in FIG. 2. In this arrangement, wireless signals, such as acoustic signals in many embodiments, are sent from each of the sensor communications nodes to a corresponding receiver communications node. The receiver communications nodes, in turn, send an electrical or optical signal up to the receiver via the communications wire.

In one aspect, a portion of the communications wire is a communications link between a wellhead at the surface and the receiver. The link may be, for example, an electrical conduit or cable that meets Class I, Division I requirements.

The method 700 also provides for processing signals received by the receiver. This is indicated at Box 770. The receiver has data acquisition capabilities. The receiver may employ either volatile or non-volatile memory. The signals are processed for analysis of the one or more subsurface conditions. Analysis may be by an operator, by software, or both.

As can be seen, a novel downhole telemetry system is provided, as well as a novel method for the electro-acoustic transmission of information using a plurality of data transmission nodes.

The downhole telemetry system may be used to adjust the flow of production fluids into a wellbore. Thus, a method for of activating a sliding sleeve in a wellbore is also provided herein.

In one aspect, the method includes placing a sliding sleeve along a tubular body within the wellbore. The tubular body may be, for example, a joint of casing or a joint of liner or even a base pipe in a sand screen. The sliding sleeve resides proximate a depth of a subsurface formation.

The method also includes running a production tubing into the wellbore. The production tubing has a communications wire placed substantially along its length. The wire is preferably an insulated electrically conductive wire.

Additionally, the method comprises securing a receiver communications node onto the production tubing. The receiver communications node is secured proximate the subsurface formation. The receiver communications node is configured to receive electrical signals from a surface, and then transmit those signals as one or more of low or high frequency acoustic waves, radio waves, low frequency or inductive electromagnetic waves, and light.

The method also includes providing a series of acoustic communications nodes along the wellbore. The acoustic communications nodes are spaced along the tubular body from the receiver communications node down to the sliding sleeve. In one aspect, the series of acoustic communications nodes comprises at least five acoustic communications nodes, and the acoustic communications nodes are spaced apart at one node per joint of pipe.

The sensor communications nodes are configured to receive an acoustic signal, and transmit that acoustic signal down to the sliding sleeve, node-to-node. The acoustic communications nodes may be in accordance with the node 400 described above in FIGS. 4A-4C.

The method additionally includes sending a signal from the surface, through the receiver communications node, through the series of acoustic communications nodes, and to the sliding sleeve. This serves to activate the sliding sleeve and change the flow of production fluids into the production tubing. The sliding sleeve is preferably powered by a downhole battery.

Activating the sliding sleeve may comprise (i) partially closing the sliding sleeve, thereby reducing a flow of production fluids into the production tubing, (ii) completely closing the sliding sleeve, thereby shutting off a flow of production fluids into the production tubing, (iii) partially opening the sliding sleeve, thereby increasing a flow of production fluids into the production tubing, or (iv) opening the sliding sleeve, thereby exposing the production tubing to the flow of production fluids.

While it will be apparent that the inventions herein described are well calculated to achieve the benefits and advantages set forth above, it will be appreciated that the inventions are susceptible to modification, variation and change without departing from the spirit thereof. 

1. A method of transmitting data along a wellbore up to a surface, comprising: placing one or more downhole sensors along the wellbore proximate a depth of a subsurface formation; generating signals at the downhole sensors that are indicative of one or more subsurface conditions; providing one or more sensor communications nodes along the wellbore, each sensor communications node configured to process signals generated by a downhole sensor, and transmit those signals as acoustic signals; providing a receiver at a surface; providing a production tubing in the wellbore, the production tubing having a communications wire placed substantially along its length; securing at least one receiver communications node onto the production tubing proximate the subsurface formation, wherein the receiver communications node is configured to receive acoustic signals across a fluid medium within the wellbore from at least one of the sensor communications nodes, and transmit those signals via the communications wire to the receiver; and processing signals received by the receiver for analysis of the one or more subsurface conditions.
 2. The method of claim 1, wherein the surface is an earth surface.
 3. The method of claim 1, wherein the surface is a water surface.
 4. The method of claim 1, wherein the sensors are (i) pressure sensors, (ii) temperature sensors, (iii) induction logs, (iv) gamma ray logs, (v) formation density sensors, (vi) sonic velocity sensors, (vii) vibration sensors, (viii) resistivity sensors, (ix) flow meters, (x) microphones, (xi) geophones, (xii) strain gauges, or (xiii) combinations thereof.
 5. The method of claim 4, wherein each of the sensor communications nodes comprises: a housing having a sealed bore, with the housing being fabricated from a material having a resonance frequency that is within the frequency band used for the acoustic signals; an electro-acoustic transducer and associated transceiver residing within the bore for transmitting signals from the sensor as acoustic signals; and an independent power source residing within the bore providing power to the transceiver.
 6. The method of claim 5, wherein each of the one or more downhole sensors resides within the housing of a corresponding sensor communications node.
 7. The method of claim 5, wherein each of the one or more downhole sensors resides adjacent the housing of a corresponding sensor communications node, and is in electrical communication with the corresponding electro-acoustic transducer.
 8. The method of claim 5, wherein: running a production tubing into the wellbore comprises threadedly coupling joints of pipe together end-to-end, and lowering the joints of pipe into the wellbore; and the communications wire is an insulated electrical wire or a fiber optic cable that is secured to an outer diameter of the production tubing along the joints of pipe, extending from the receiver down to the one or more receiver communications nodes.
 9. The method of claim 8, wherein: each of the sensor communications nodes further comprises at least one clamp for radially attaching the communications node onto an outer surface of a subsurface pipe; the subsurface pipe represents a joint of casing, a joint of liner, or a base pipe of a joint of sand screen; and the step of providing two or more sensor communications nodes along the wellbore comprises clamping the communications nodes to an outer surface of the subsurface pipe.
 10. The method of claim 9, wherein the at least one clamp comprises: a first arcuate section; a second arcuate section; a hinge for pivotally connecting the first and second arcuate sections; and a fastening mechanism for securing the first and second arcuate sections around an outer surface of the subsurface pipe.
 11. The method of claim 9, wherein: each of the one or more sensor communications nodes communicates wirelessly with a corresponding receiver communications node; and each of the at least one receiver communications node receives acoustic signals from the corresponding sensor communications nodes, and transmits those signals to the receiver via the communications wire.
 12. The method of claim 9, wherein: each of the one or more sensor communications nodes is configured to transmit acoustic signals up to a next sensor communications node, node-to-node, using the subsurface pipe as a carrier medium, with a last sensor communications node transmitting acoustic signals representing the one or more subsurface conditions to a single receiver communications node; and the at least one receiver communications node comprises the single receiver communications node.
 13. The method of claim 12, wherein: the electro-acoustic transceivers in the one or more sensor communications nodes receive acoustic waves at a first frequency, and re-transmit the acoustic waves at a second different frequency; and the electro-acoustic transceivers listen for the acoustic waves generated at the first frequency for a longer time than the time for which the acoustic waves were generated at the first frequency by a previous communications node.
 14. A downhole acoustic telemetry system, comprising: one or more downhole sensors residing along a wellbore proximate a depth of a subsurface formation, each of the downhole sensors configured to sense a subsurface condition and send a signal indicative of that subsurface condition; one or more sensor communications nodes also residing along the wellbore proximate a depth of the subsurface formation, wherein each of the sensor communications nodes comprises: a housing having a sealed bore, with the housing being fabricated from a material having a resonance frequency that is within the frequency band used for the acoustic signals; an electro-acoustic transducer and associated transceiver residing within the bore for transmitting signals from the sensor as acoustic signals, and an independent power source residing within the bore providing power to the transceiver; a receiver residing proximate a surface; a string of production tubing within the wellbore, the wellbore comprising a fluid medium within the wellbore; a communications wire placed substantially along a length of the string of production tubing; and at least one receiver communications node secured to the string of production tubing proximate the subsurface formation, wherein the receiver communications node is configured to receive acoustic signals via the fluid medium from the at least one of the sensor communications nodes, and transmit those signals via the communications wire to the receiver.
 15. The acoustic telemetry system of claim 14, wherein the sensors are (i) pressure sensors, (ii) temperature sensors, (iii) induction logs, (iv) gamma ray logs, (v) formation density sensors, (vi) sonic velocity sensors, (vii) vibration sensors, (viii) resistivity sensors, (ix) flow meters, (x) microphones, (xi) geophones, (xii) strain gauges, or (xiii) combinations thereof.
 16. The acoustic telemetry system of claim 15, wherein each of the one or more downhole sensors resides within the housing of a corresponding sensor communications node.
 17. The acoustic telemetry system of claim 15, wherein each of the one or more downhole sensors resides adjacent the housing of a corresponding sensor communications node, and is in electrical communication with the corresponding electro-acoustic transducer.
 18. The acoustic telemetry system of claim 15, wherein: the production tubing comprises a plurality of joints of pipe threadedly coupled together end-to-end; and the communications wire is an insulated electrical wire or a fiber optic cable that is secured to an outer diameter of the production tubing along the joints of pipe.
 19. The acoustic telemetry system of claim 18, wherein: each of the sensor communications nodes further comprises at least one clamp; the subsurface pipe represents a joint of casing, a joint of liner, or a base pipe within a joint of sand screen; and each of the two or more sensor communications nodes is clamped onto an outer surface of the subsurface pipe.
 20. The acoustic telemetry system of claim 19, wherein the at least one clamp comprises: a first arcuate section; a second arcuate section; a hinge for pivotally connecting the first and second arcuate sections; and a fastening mechanism for securing the first and second arcuate sections around an outer surface of the subsurface pipe.
 21. The acoustic telemetry system of claim 20, wherein: the housing of each of the sensor communications nodes comprises a first end and a second opposite end; and the at least one clamp comprises a first clamp secured at the first end of the housing, and a second clamp secured at the second end of the housing.
 22. The acoustic telemetry system of claim 21, wherein: each of the communications nodes further comprises a first shoe at the first end of the housing and a second shoe at the second end of the housing; the first shoe and the second shoe each comprises: a beveled edge designed to face away from the tubular body, a flat surface designed to face towards the tubular body, and a shoulder providing a clearance between the flat surface and the tubular body configured to receive a clamp.
 23. The acoustic telemetry system of claim 19, wherein: each of the one or more sensor communications nodes is configured to wirelessly communicate with a corresponding receiver communications node; and the receiver communications nodes are configured to receive acoustic signals from the corresponding sensor communications nodes, and transmit those signals to the surface via the communications wire.
 24. The acoustic telemetry system of claim 19, wherein: each of the one or more sensor communications nodes is configured to transmit acoustic signals up to a next sensor communications node, node-to-node, using the subsurface pipe as a carrier medium, with a last sensor communications node transmitting acoustic signals representing the one or more subsurface conditions to a single receiver communications node; the at least one receiver communications node comprises the single receiver communications node; and the single receiver communications node is configured to receive acoustic signals from the corresponding sensor communications nodes, and transmit those signals to the surface via the communications wire.
 25. The acoustic telemetry system of claim 24, wherein: the electro-acoustic transceivers in the one sensor communications nodes receive acoustic waves at a first frequency, and re-transmit the acoustic waves at a second different frequency; and the electro-acoustic transceivers listen for the acoustic waves generated at the first frequency for a longer time than the time for which the acoustic waves were generated at the first frequency by a previous communications node.
 26. The acoustic telemetry system of claim 24, wherein a frequency band for the acoustic wave transmission by the transceivers operates from 50 kHz to 500 kHz.
 27. A method of activating a sliding sleeve in a wellbore, comprising: placing a sliding sleeve along a tubular body within the wellbore, the sliding sleeve residing proximate a depth of a subsurface formation; providing a production tubing in the wellbore, the production tubing having a communications wire placed substantially along its length; securing a receiver communications node onto the production tubing proximate the subsurface formation, wherein the receiver communications node is configured to receive electrical signals from a surface, and transmit those signals as acoustic signals via a fluid medium in the wellbore; providing a series of acoustic communications nodes along the wellbore down to the sliding sleeve, the sensor communications nodes being configured to receive an acoustic signal transmitted from the receiver communications node via the fluid medium, and transmit that acoustic signal down to the sliding sleeve, node-to-node, with each acoustic communications node comprising: a housing having a sealed bore, with the housing being fabricated from a material having a resonance frequency that is within the frequency band used for the acoustic signal; an electro-acoustic transducer and associated transceiver residing within the bore for transmitting signals from the receiver communications node as acoustic signals, and an independent power source residing within the bore providing power to the transceiver; and sending a signal from the surface, through the receiver communications node, through the series of acoustic communications nodes, and to the sliding sleeve, thereby activating the sliding sleeve and changing a flow of production fluids into the production tubing.
 28. The method of claim 27, wherein the surface is an earth surface.
 29. The method of claim 27, wherein the surface is a water surface.
 30. The method of claim 27, wherein the tubular body is a joint of casing or a joint of liner.
 31. The method of claim 27, wherein the sliding sleeve is powered by a downhole battery.
 32. The method of claim 27, wherein activating the sliding sleeve comprises (i) partially closing the sliding sleeve, thereby reducing a flow of production fluids into the production tubing, (ii) completely closing the sliding sleeve, thereby shutting off a flow of production fluids into the production tubing, (iii) partially opening the sliding sleeve, thereby increasing a flow of production fluids into the production tubing, or (iv) opening the sliding sleeve, thereby exposing the production tubing to the flow of production fluids.
 33. The method of claim 27, wherein: the series of acoustic communications nodes comprises at least five acoustic communications nodes; and the acoustic communications nodes are spaced apart at one node per joint of pipe. 